Not Applicable.
The present invention relates to a method and an apparatus for the reduction or elimination of the buildup of solids in a system or conduit, such as a conduit for the transport of typical hydrocarbon streams produced from oil or gas wells (mixture of crude oil, condensate, fresh water or brine, natural gas). The invention has special relevance to deep water subsea wells where phase separation and purification is difficult, but is not limited to only deep waters. More particularly, the present invention relates to a method for precipitating solids dissolved in the produced stream, in a treatment apparatus positioned upstream of the system or conduit, as well as precipitating other solids formed when mixed phases are at selected pressures and temperatures. An example of the latter is the creation of solid natural gas hydrates as a mixture of gas and water is cooled under pressure. Further, the present invention relates, but is not limited, to precipitation driven by cooling the stream in the treatment apparatus to or near the ambient temperature surrounding the system or conduit. Still further, the present invention relates to a treatment apparatus including a flow passage having a sufficient size and length to effect precipitation and/or deposition of created solids, and a removal device adapted to remove said solids in a fashion such that they can be transported in the subsequent conduit without flow interruptions.
Typically, when crude oil is produced from a reservoir, it contains water, gas, and dissolved solids, such as wax, asphaltene, organic salts, and inorganic salts. Waxes, or high molecular weight paraffins, found in crude oil production systems generally include branched and straight, high carbon number (average carbon numbers of 18+, more particularly 40+) alkane hydrocarbon chains. An alkane is a hydrocarbon molecule having the general empirical formula CnH2n+2, where n, the carbon number, is a positive integer. Asphaltene is defined as the fraction of the crude oil insoluble in n-heptane, but soluble in toluene. Asphaltenes are complex polar macro-cyclic molecules that typically contain carbon, hydrogen, nitrogen, oxygen, and sulphur. The inorganic salts that may be present include any inorganic salt typically present in produced streams and which may precipitate to form salt deposits known as scale. Such inorganic salts include sulfates, for example BaSO4, CaSO4, and SrSO4, and carbonates, for example CaCO3, MgCO3, and FeCO3, in addition to the more common chlorides of sodium, calcium, and magnesium. The inorganic salts that may be present also include silicon oxides, such as SiO2, or more commonly various silicates. A salt generally is an ionic complex between a positively charged cation, for example Ca2+, and a negatively charged anion, for example SO42xe2x88x92. An organic salt is a salt that is a compound of carbon and therefore includes a carbon-containing cation.
Some of these dissolved solids may precipitate as a thermodynamic parameter, such as temperature or pressure, changes. For instance, the solubility of wax decreases with temperature reduction and with pressure reduction, especially if such results in liquid hydrocarbon shrinkage as the lighter components flash to the vapor phase. The xe2x80x9ccloud pointxe2x80x9d of a fluid, also referred to as the xe2x80x9cwax appearance temperaturexe2x80x9d is the temperature at which wax first appears in solid form as the fluid cools. Normally, this data is taken at atmospheric pressure; substantially higher pressures typically require cooler temperatures before precipitation is induced. Similarly, salt solubilities typically decrease with decreasing temperature and decreasing pressure. Asphaltenes form primarily due to a decrease in pressure. When the pressure drops to the bubble point pressure, the asphaltene molecules may precipitate in some systems, typically ones rich in paraffins and poor in resins and aromatics. Further, asphaltene solubility below the fluid bubble point decreases with rising temperature. Sometimes, asphaltene deposition may occur with wax deposition.
Further, some of these dissolved solids may precipitate as chemical composition parameters change, such as composition changes caused by mixing of two or more fluid streams. For example, hydrate, salt, and asphaltene precipitation can also be caused on mixing of two or more streams. For instance, hydrates may precipitate on mixture with fresh water, asphaltene precipitation can be induced by the addition of lower paraffins, multiple brine mixtures can lead to incompatibilities resulting in the precipitation of one or more of the salts.
As indicated previously, the precipitation of solids may also be induced by phase changes of one or more of the fluid components. For instance, water may form ice on sufficient cooling and water and certain light gases may form clathrate hydrates (for example, as described in Natural Hydrates Of Natural Gases, E. D. Sloan, Marcel Dekker, Inc. N.Y., 1997) at lower temperatures or higher pressures or a combination of the two effects. Specifically, the lighter gases include the lower hydrocarbon gases with less than 5 hydrocarbons as well as CO2, H2S, N2, and the like. When a flowing stream is cooled below the hydrate dissociation temperature, the temperature, calculated or measured, at a given pressure at which hydrates will dissociate into water and gas, then water present in the system will tend to combine with the light gases to form solid hydrates.
In extracting oil from a reservoir and transporting it, precipitation may. occur at any one of the stages along the flow, including in the formation near the well bore, within the well, and beyond the well, in a conduit or pipeline, especially if the pipelines are multi-phase, cold sub-sea lines. In the formation near the well and at the well bottom, the crude temperature is normally higher than the cloud point or hydrate dissociation temperature, avoiding wax and hydrate precipitation, however, salts and asphaltenes can and have precipitated due to pressure draw down. As the crude oil travels up the well, the temperature and pressure drop, which may cause additional solids precipitation. At the well head, the pressure may be reduced further by a choke to stay within flow line pressure limits (LPL""s); the pressure drop across the choke will induce additional cooling (Joule-Thomson expansion) both of which may cause further precipitation of wax, salt, and hydrate. After the choke sub-sea well streams enter multi-phase flowlines for transport to shallow water, surface piercing structures where the streams are separated. The flow in deep water flowlines is further cooled by the cold waters (typically 40 F) surrounding the flowlines.
On the other hand, late in the life of the well, as the depleted field pressure declines, the wellhead pressure may need to be raised by multiphase pumps or other means in order to overcome the hydrostatic pressure resulting from the elevation increase to the host platform. The increased pressure may induce hydrate formation. Beyond the wellhead, with or without increased pressures by artificial compression, the produced fluid has to pass through the flow line or lines, such as tiebacks, to the host facility.
Deep water subsea flowlines are used to transport oil, gas, and aqueous fluids from subsea well(s) to a host facility where the fluids are separated and treated for sale. The flowlines may combine fluids from several wells or even several fields; that is, several different fluids may be mixed. In particular, extended tieback systems are useful for the development of small fields in deep waters, by tying back subsea trees or manifolds that are remote from processing facilities. These deep water flow lines are typically cold, near (rarely below) the freezing point of water.
When the cooling occurs in a flowing pipeline, well or similar conduit, the formation of waxy or paraffinic, hydrate, asphaltic, and salt solids is undesirable, as the solids build up in the conduit by partially depositing onto the walls or settling to the bottom, both of which reduce the flow cross-sectional area, and eventually lead to local spalling of the deposit which tends to plug the pipeline ahead. This can result in shut-in of the line and temporary cessation of well production. A buildup usually is caused by a deposition process where the solids form on the system walls and continue to grow so as to obstruct the system or conduit.
Typically, the solids deposition on the flow line inner wall continues as long as the fluid temperature is greater than the wall xe2x80x9csurfacexe2x80x9d temperature the fluid sees, there is flow, and the pressure is conducive for solid formation. Isothermal conditions do not lead to deposition but still may induce limited solids formation (due to sub-cooling effects) and gravitational drop out when flow is stopped. In general it is recognized that solids that settle as flow is stopped are unlikely to form true deposits but rather tend to be removed as flow is re-initiated. Any buildup of solids reduces the cross-sectional area for flow or the volume of treating vessels, which can lead to reduced throughput and eventual total obstruction. Thus, it is desirable to provide a system or method that assures passage of fluid through a flow line, such as a sub-sea tie-back.
For short tiebacks, such as those less than 15 miles, in deep water (where the ocean temperature is about 40xc2x0 F.), one approach to flow assurance involves the insulation of twin flow lines to maintain the stream temperature above the cloud point or hydrate formation temperature during normal flow, reduced flow near the project end and in case of shut-ins lasting less than several hours. Twin flowlines are employed to allow round-trip pigging from the receiving facility. This method has the disadvantage that it requires two flowlines and the amount of insulation required increases with increasing length of the pipeline, reduced flow, and account of shut-ins. Thus, this method is economically unfeasible for longer flow lines.
In another technique, chemicals that delay hydrate formation to lower temperatures are injected into the stream. For example, the formation of hydrates can be inhibited thermodynamically at selected, and usually mild, conditions by a variety of alcohols and salts. In yet another technique hydrate and wax deposition onto conduit walls can be avoided by a variety of surface active agents (anti-agglomerants, kinetic inhibitors, surface wetting agents, or nucleating agents). Chemical treatments are generally more expensive in the long run than twin insulated lines, but they can handle any distance tiebacks.
These methods can be used alone, in combination with multiple chemical treatments, or in combination with the use of thermal insulation.
Blocked flowlines require remediation methods. Such methods include, but are not limited to, coiled tubing drilling, jetting, dissolution, as well as thermal treatments (hot oiling or in-situ heat generation), and pressure reduction (for hydrates and wax only) or a combination of such. These same methods are applicable to the present invention in case of some unanticipated failure.
Notwithstanding the teachings disclosed above, there remains a need in the art for an economical and effective system and method for reducing or eliminating build-up of solids in deep water subsea flowlines. The present invention overcomes the deficiencies of the prior art, as will be demonstrated.
The present invention allows the use of single or multiple, bare or uninsulated flowlines for the evacuation of produced streams from hydrocarbon wells at cold ambient temperatures and high pressures. The invention features a process and apparatus for preparing a stream produced from an oil or gas well for subsea transport in a multi-phase, cold, relatively high pressure uninsulated conduit, including passing the stream through a process and apparatus under conditions sufficient to precipitate and/or deposit solids in the apparatus; removing said solids from the process; suspending the solids in the stream, forming a slurry or otherwise transportable suspension or solids distribution; and passing the slurry/suspension/distribution to a conduit connected to additional processing facilities at substantial distances from the well in a fashion to avoid/reduce plugging of said conduit. The invention is especially applicable to deep water subsea wells, but is not limited to such.
The above mentioned precipitation/deposition is caused by cooling of the stream by the ambient ocean temperature, Joule-Thomson expansion due to pressure losses, mechanically induced cooling (heat pumps, etc.), addition of cooling agents (solid CO2, etc), as well as nucleation inducing agents, or a combination of the above. Discussions of cooling processes for waxy oil are given in U.S. Pat. Nos. 4,697,426 and 4,702,758, both which are incorporated herein by reference.
In another aspect, the present invention features a treatment process and apparatus for precipitating solids dissolved in the stream, or otherwise generated solids by process variable changes, including a flow passage having an outer surface exposed to a lower temperature than the temperature of the stream, an inner surface, and a length sufficient to promote cooling of the stream and precipitation of said solids in the cooled stream or on said inner surface and a removal element adapted to remove at least a portion of said solids from said inner surface or the stream so as to avoid continued solids build-up in the treatment process and eventual plugging of the flow passage or downstream conduit.
Specifically, the present invention features a treatment apparatus for precipitating solids dissolved in the stream, or otherwise induced to precipitate, the stream passing from said treatment apparatus to a flow line, the apparatus including a tubular structure comprising a loop adjacent said flow line and having an inner surface and an outer surface, with the outer surface contacting sea water at a temperature such that the solid precipitates on the inner surface and in the stream. The apparatus further includes a mechanical element adapted to remove said solid from said inner surface and the stream.
More specifically, the above described cooling by the ambient deep water ocean can be augmented by additional cooling methods near the termination of the apparatus to reduce the length or size of the apparatus such as Joule-Thomson cooling, mechanical cooling (heat pumps), or injection of coolants.
Thus, the present invention comprises a combination of features and advantages that enable it to overcome various problems of prior methods. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments of the invention, and by referring to the accompanying drawings.
It is understood that throughout this specification flow refers to the net local movement of a portion of a fluid across a notional plane, such as defining a local cross-section of a flow structure, such as a flow line, a pipeline, a flow passage, a tubular structure, and the like.